After a gas well or borehole is drilled, it is completed according to the determination of active zones that are usually localized within small segments of the several thousand feet of well bore. Completion may consist of stimulation of active zones, the sealing off of inactive zones by the insertion and cementing of tubing, the sealing off of active and inactive zones by tubing and the subsequent artificial perforation of the tubing in active zones. A presumption of all of this is that the active zones can be located and a downhole flowmeter is the most direct way of doing this. The flowmeter is lowered down the hole on a cable from a standard logging truck. Active zones are located by step like drops in the flow rate corresponding to the areas where the flow up the borehole is augmented by additional gas entering the borehole from the formation.
Normally, flow in the borehole may be expected to decrease as the meter is lowered reaching a flow of zero at the bottom. However, wells that are on line may be kept under pressure and it is possible that some imperfection in the completion process may result in gas leaving the borehole and entering the formation. Under these conditions step increases in flow rate may be observed in a well operated under pressure indicating that not all the gas which is produced is getting to the surface.
Although a wide range of types of flowmeters exist, only the turbine meter is in regular use as a downhole flowmeter. In this device a propeller is lowered down the well bore and gas entry points are located by changes in the rate of rotation of the propeller. This meter has at least two disadvantages. First, the desired quantity is the volume or mass flow of the gas, not the velocity of it. Conversion from one to the other requires knowledge of the bore cross sectional area and the flow profile within this area, quantities which are only known approximately. Second, the minimum velocity that a turbine meter will measure is variously placed at fifty to one hundred MCFD (volume flow equivalent). Many commercial wells, particularly in the Appalachian basin, have a total flow rate at the surface which is less than this minimum measurable quantity. Thus the turbine meter is not useful for these wells. Further, many wells that eventually produce over one hundred MCFD, do so only after stimulation of the active zones. The turbine meter is not useful for the predetermination of these potentially active zones.
The limited value of the turbine meter has lead to the use of several other tools to indicate gas entry points into the well bore. Among these is the sonic or noise meter that seeks to locate gas entry points or location of points where hissing or other noises can be heard. A difficulty of this meter is that some gas entry points are quiet.
Another meter is the temperature meter that locates gas entry points by anomalous decreases in temperature. Although the quoted reason for this anomalous decrease is the "Joule Thompson" cooling effect upon expansion, the actual response of the temperature tool is a complicated function of the amount of gas desorption, Joule Thompson expansion, the length of the conduit or fracture from the gas source to the borehole, the original temperature of the rock, time, and the dilution of the cooler gas entering the borehole by the flow of gas up the borehole from lower entry points.
The use of both sonic and temperature logs either sequentially or in tandem on a single cable confirms the vagaries of each in that often one will locate a gas entry point where the other fails. It is not clear that both tools used together will locate all gas entry points because the percentage of entry points which are both quiet and without cooling is unknown. Further, neither tool gives a quantitative estimate of the size of the gas entry point. In spite of these serious problems, these tools are in regular use in some areas because they are the best tool available.
There have been at least two prior attempts to overcome some of these difficulties. One was to utilize a thermoresistive element as a flow sensor. This device worked well in the laboratory and had real strength in the low flow regime. However, in the first (and only) field test the device proved to be very sensitive to the considerable mud present in the borehole environment. A second device used a pair of acoustic transducers to measure flow in conjunction with the Doppler effect. Both meters address only the low flow problem; neither measures mass or volume flow rate directly. It is believed that these two instruments are unknown in the oil and gas industry and are not public knowledge.
The measurement of the amount of dilution as a means of determining the flow rate of the diluent has had some prior use. For example, a technique that has been used to determine the flow rate of a stream or river is to inject into it a fluorescent dye at a known and constant flow rate. By measuring the concentration of the dye at a point sufficiently down stream so that complete mixing has occurred, one can determine the volume flow rate of the stream from the measured concentration, the original concentration of the undiluted dye, and the injection rate of the dye. U.S. Pat. Nos. 4,197,456 and 4,107,525 deal with devices of this type for liquid flow. This process has been extended to gases as described in U.S. Pat. No. 4,178,919 dealing with the injection of tracers to determine the uptake of oxygen in respiratory gases. However, there is no previous mention of use of such devices for gas wells. U.S. Pat. No. 4,532,812 discloses using two acoustic transducers in measuring the flow of gases.